1. Field of the Invention
This invention relates to a process for simultaneously upgrading and recovering heavy crude oils and natural bitumens from subsurface reservoirs.
2. Description of the Prior Art
Worldwide deposits of natural bitumens (also referred to as "tar sands") and heavy crude oils are estimated to total more than five times the amount of remaining recoverable reserves of conventional crude [References 1,5]. But these resources (herein collectively called "heavy hydrocarbons") frequently cannot be recovered economically with current technology, due principally to the high viscosities which they exhibit in the porous subsurface formations where they are deposited. Since the rate at which a fluid flows in a porous medium is inversely proportional to the fluid's viscosity, very viscous hydrocarbons lack the mobility required for economic production rates.
Steam injection has been used for over 30 years to produce heavy oil reservoirs economically by exploiting the strong negative relationship between viscosity and temperature that all liquid hydrocarbons exhibit. This relationship is illustrated in the drawing labeled FIG. 6, which includes plots 601, 603, 605, and 607 of viscosity as a function of temperature for heavy hydrocarbons from, respectively, the Street Ranch, Saner Ranch, Athabasca, and Midway Sunset deposits [Reference 6].
In one method of steam-assisted production, steam is injected into a formation through a borehole so that a portion of the heavy oil in the formation is heated, thereby significantly reducing its viscosity and increasing its mobility. Steam injection is then halted and the oil is produced through the same borehole. In a second method, after the oil-bearing formation is preheated sufficiently by steam injection into all boreholes, steam is continuously injected into the formation through a set of injection boreholes to drive oil to a set of production boreholes.
Referring again to FIG. 6, the plots show that heating the heavy hydrocarbons from say 100.degree. F., a typical temperature for the subsurface deposits in which the hydrocarbons are found, to 400.degree. F., a temperature that could be achieved in a subsurface deposit by injecting steam from the surface, reduces the viscosity of each of the four hydrocarbons by three to four orders of magnitude. Such viscosity reductions will not, however, necessarily result in economic production. The viscosity of Midway Sunset oil at 400.degree. F. approaches that of a conventional crude, which makes it economic to produce. But even at 400.degree. F., the viscosities of the bitumens from Athabasca, Street Ranch, and Saner Ranch are 50 to 100 times greater than the levels required to ensure economic rates of recovery. Moreover, the high viscosities of many heavy hydrocarbons, when coupled with commonly encountered levels of formation permeability, make the injection of steam or other fluids which might be used for heating a hydrocarbon-bearing formation difficult or nearly impossible.
In addition to high viscosity, heavy hydrocarbons often exhibit other deleterious properties which cause their refining into marketable products to be a significant challenge. These properties are compared in Table 1 for an internationally-traded light crude, Arabian Light, and three heavy hydrocarbons.
TABLE 1 Properties of Heavy Hydrocarbons Compared to a Light Crude Light Crude Heavy Hydrocarbons Properties Arabian Light Orinoco Cold Lake San Miguel Gravity, .degree. API 34.5 8.2 11.4 -2 to 0 Viscosity, cp @ 10.5 7,000 10,700 &gt;1,000,000 100.degree. F. Sulfur, wt % 1.7 3.8 4.3 7.9 to 9.0 Nitrogen, wt % 0.09 0.64 0.45 0.36 to 0.40 Metals, wppm 25 559 260 109 Bottoms (975.degree. F.+), 15 59.5 51 71.5 vol % Conradson carbon 4 16 13.1 24.5 residue, wt %
The high levels of undesirable components found in the heavy hydrocarbons shown in Table 1, including sulfur, nitrogen, metals, and Conradson carbon residue, coupled with a very high bottoms yield, require costly refining processing to convert the heavy hydrocarbons into product streams suitable for the production of transportation fuels.
Two fundamental alternatives exist for the upgrading of heavy hydrocarbon fractions: carbon rejection and hydrogen addition.
Carbon-rejection schemes break apart (or "crack") carbon bonds in a heavy hydrocarbon fraction and isolate the resulting asphaltenes from the lighter fractions. As the asphaltenes have significantly higher carbon-to-hydrogen ratios and higher concentrations of contaminants than the original feed, the product stream has a lower carbon-to-hydrogen ratio and significantly less contamination than the feed. Although less expensive than hydrogen-addition processes, carbon rejection has major disadvantages--significant coke production and low yields of liquid products which are of inferior quality. PA1 Hydrogen-addition schemes convert unsaturated hydrocarbons to saturated products and high-molecular-weight hydrocarbons to hydrocarbons with lower molecular weights while removing contaminants without creating low-value coke. Hydrogen addition thereby provides a greater volume of total product than carbon rejection. The liquid product yield from hydrogen-addition processes can be 20 to 25 volume percent greater than the yield from processes employing carbon rejection. But these processes are expensive to apply and employ severe operating conditions. Catalytic hydrogenation, with reactor residence times of one to two hours, operate at temperatures in the 700 to 850.degree. F. range with hydrogen partial pressures of 1,000 to 3,000 psi. PA1 Justheim, U.S. Pat. No. 3,327,782 modulates (heats or cools) hydrogen at the surface. In order to initiate the desired objectives of "distilling and hydrogenation" of the in situ hydrocarbon, hydrogen is heated on the surface for injection into the hydrocarbon-bearing formation. PA1 Hujsak, U.S. Pat. No. 4,448,251 teaches that hydrogen is obtained from a variety of sources and includes the heavy oil fractions from the produced oil which can be used as reformer fuel. Hujsak also includes and teaches the use of forward or reverse in situ combustion as a necessary step to effect the objectives of the process. Furthermore, heating of the injected gas or fluid is accomplished on the surface, an inefficient means of heating compared to using a downhole combustion unit because of heat losses incurred during transportation of the heated fluids to and down the borehole. PA1 Stine, U.S. Pat. No. 4,448,251 utilizes a unique process which incorporates two adjacent, non-communicating reservoirs in which the heat or thermal energy used to raise the formation temperature is obtained from the adjacent reservoir. Stine utilizes in situ combustion or other methods to initiate the oil recovery process. Once reaction is achieved, the desired source of heat is from the adjacent zone. PA1 Gregoli, U.S. Pat. No. 4,501,445 teaches that a crude formation is subjected to fracturing to form "an underground space suitable as a pressure reactor," in situ hydrogenation, and conversion utilizing hydrogen and/or a hydrogen donor solvent, recovery of the converted and produced crude, separation at the surface into various fractions, and utilization of the heavy residual fraction to produce hydrogen for re-injection. Heating of the injected fluids is accomplished on the surface which, as discussed above, is an inefficient process. PA1 Ware, U.S. Pat. No. 4,597,441 describes in situ "hydrogenation" (defined as the addition of hydrogen to the oil without cracking) and "hydrogenolysis" (defined as hydrogenation with simultaneous cracking). Ware teaches the use of a downhole combustor. Reference is made to previous patents relating to a gas generator of the type disclosed in U.S. Pat. Nos. 3,982,591; 3,982,592; or 4,199,024. Ware further teaches and claims injection from the combustor of superheated steam and hydrogen to cause hydrogenation of petroleum in the formation. Ware also stipulates that after injecting superheated steam and hydrogen, sufficient pressure is maintained "to retain the hydrogen in the heated formation zone in contact with the petroleum therein for `soaking` purposes for a period of time." In some embodiments Ware includes combustion of petroleum products in the formation--a major disadvantage, as discussed earlier--to drive fluids from the injection to the production wells. PA1 a. inserting downhole combustion units within injection boreholes, which communicate with production boreholes by means of horizontal fractures or by multiple horizontal boreholes extended from the injection boreholes, at or near the level of the subsurface formation containing a heavy hydrocarbon; PA1 b. for a first preheat period, flowing from the surface through said injection boreholes stoichiometric proportions of a reducing gas mixture and an oxidizing fluid to said downhole combustion units and igniting same in said downhole combustion units to produce hot combustion gases, including superheated steam, while flowing partially saturated steam from the surface through said injection boreholes to said downhole combustion units to control the temperature of said heated gases and to produce additional superheated steam; PA1 c. injecting said superheated steam into the subsurface formation to heat a region of the subsurface formation to a preferred temperature; PA1 d. for a second conversion period, increasing the ratio of reducing gas to oxidant in the mixture fed to the downhole combustion units, or injecting reducing gas in the fluid stream controlling the temperature of the combustion units, to provide an excess of reducing gas in the hot gases exiting the combustion units; PA1 g. continuously injecting the heated excess reducing gas and superheated steam into the subsurface formation to provide preferred conditions and reactants to sustain in situ hydrovisbreaking and thereby upgrade the heavy hydrocarbon; PA1 h. collecting continuously at the surface, from said production boreholes, production fluids comprised of converted liquid hydrocarbons, unconverted virgin heavy hydrocarbons, residual reducing gases, hydrocarbon gases, solids, water, hydrogen sulfide, and other components for further processing.
Converting heavy crude oils and natural bitumens to upgraded liquid hydrocarbons while still in a subsurface formation, which is the object of the present invention, would address the two principal shortcomings of these heavy hydrocarbon resources--the high viscosities which heavy hydrocarbons exhibit even at elevated temperatures and the deleterious properties which make it necessary to subject them to costly, extensive upgrading operations after they have been produced. However, the process conditions employed in refinery units to upgrade the quality of liquid hydrocarbons would be extremely difficult to achieve in the subsurface. The injection of catalysts would be exceptionally expensive, the high temperatures used would cause unwanted coking in the absence of precise control of hydrogen partial pressures and reaction residence time, and the hydrogen partial pressures required could cause random, unintentional fracturing of the formation with a potential loss of control over the process.
A process occasionally used in the recovery of heavy crude oil and natural bitumen which to some degree converts in the subsurface heavy hydrocarbons to lighter hydrocarbons is in situ combustion. In this process an oxidizing fluid, usually air, is injected into the hydrocarbon-bearing formation at a sufficient temperature to initiate combustion of the hydrocarbon. The heat generated by the combustion warms other portions of the heavy hydrocarbon and converts a part of it to lighter hydrocarbons via uncatalyzed thermal cracking, which may induce sufficient mobility in the hydrocarbon to allow practical rates of recovery.
While in situ combustion is a relatively inexpensive process, it has major drawbacks. The high temperatures in the presence of oxygen which are encountered when the process is applied cause coke formation and the production of olefins and oxygenated compounds such as phenols and ketones, which in turn cause major problems when the produced liquids are processed in refinery units. Commonly, the processing of products from thermal cracking is restricted to delayed or fluid coking because the hydrocarbon is degraded to a degree that precludes processing by other methods.
The present invention concerns an in situ process which converts heavy hydrocarbons to lighter hydrocarbons that does not involve in situ combustion or the short reaction residence times, high temperatures, high hydrogen partial pressures, and catalysts which are employed when conversion reactions are conducted in refineries. Rather, conditions which can readily be achieved in hydrocarbon-bearing formations are utilized; viz., reaction residence times on the order of days to months, lower temperatures, lower hydrogen partial pressures, and the absence of injected catalysts. These conditions sustain what we designate as "in situ hydrovisbreaking," conversion reactions within the formation which result in hydrocarbon upgrading similar to that achieved in refinery units through catalytic hydrogenation and hydrocracking. The present invention utilizes a unique combination of operations and associated hardware, including the use of a downhole combustion apparatus, to achieve hydrovisbreaking in formations in which high-viscosity hydrocarbons and commonly encountered levels of formation permeability combine to limit fluid mobility.
Following is a review of the prior art as related to the operations incorporated into this invention. The patents referenced teach or suggest a means for enhancing flow of heavy hydrocarbons within a reservoir, the use of a downhole apparatus for in situ operations, procedures for effecting in situ conversion of heavy crudes and bitumens, and methods for recovering and processing the produced hydrocarbons.
In U.S. Pat. No. 4,265,310, CONOCO patented the application of formation fracturing to steam recovery of heavy hydrocarbons.
Some of the best prior art disclosing the use of downhole devices for secondary recovery is found in U.S. Pat. Nos. 4,159,743; 5,163,511; 4,865,130; 4,691,771; 4,199,024; 4,597,441; 3,982,591; 3,982,592; 4,024,912; 4,053,015; 4,050,515; 4,077,469; and 4,078,613. Other expired patents which also disclose downhole generators for producing hot gases or steam are U.S. Pat. Nos. 2,506,853; 2,584,606; 3,372,754; 3,456,721; 3,254,721; 2,887,160; 2,734,578; and 3,595,316.
The concept of separating produced secondary crude oil into hydrogen, lighter oils, etc. and the use of hydrogen for in situ combustion and downhole steaming operations to recover hydrocarbons are found in U.S. Pat. Nos. 3,707,189; 3,908,762; 3,986,556; 3,990,513; 4,448,251; 4,476,927; 3,051,235; 3,084,919; 3,208,514; 3,327,782; 2,857,002; 4,444,257; 4,597,441; 4,241,790; 4,127,171; 3,102,588; 4,324,291; 4,099,568; 4,501,445; 3,598,182; 4,148,358; 4,186,800; 4,233,166; 4,284,139; 4,160,479; and 3,228,467. Additionally, in situ hydrogenation with hydrogen or a reducing gas is taught in U.S. Pat. Nos. 5,145,003; 5,105,887; 5,054,551; 4,487,264; 4,284;139; 4,183,405; 4,160,479; 4,141,417; 3,617,471; and 3,228,467.
U.S. Pat. No. 3,598,182 to Justheim; U.S. Pat. No. 3,327,782 to Hujsak; U.S. Pat. No. 4,448,251 to Stine; U.S. Pat. No. 4,501,445 to Gregoli; and U.S. Pat. No. 4,597,441 to Ware all teach variations of in situ hydrogenation which more closely resemble the current invention:
None of the patents referenced above teach the application of fracturing or related methods to the hydrocarbon-bearing formation for the purpose of enhancing fluid mobility. In contrast, the Gregoli and Ware patents both teach that injected fluids must be confined with the in situ hydrocarbons to allow time for conversion reactions to take place. Further, none of the patents referenced include in situ conversion exclusively without combustion of the hydrocarbon in the formation.
Another group of U.S. Patents--including U.S. Pat. Nos. 5,145,003 and 5,054,551 to Duerksen; U.S. Pat. No. 4,160,479 to Richardson; U.S. Pat. No. 4,284,139 to Sweany; U.S. Pat. No. 4,487,264 to Hyne; and U.S. Pat. No. 4,141,417 to Schora--all teach variations of hydrogenation with heating of the injected fluids (hydrogen, reducing gas, steam, etc.) accomplished at the surface. Further, Schora, U.S. Pat. No. 4,141,417 injects hydrogen and carbon dioxide at a temperature of less than 300.degree. F. and claims to reduce the hydrocarbon's viscosity and accomplish desulfurization. Viscosity reduction is assumed primarily through the well-known mechanism involving solution of carbon dioxide in the hydrocarbon. None of these patents includes the use of a downhole combustion unit for injection of hot reducing gases.
All of the U.S. patents mentioned are fully incorporated herein by reference thereto as if fully repeated verbatim immediately hereafter. In light of the current state of the technology, what is needed--and what has been discovered by us--is an efficient process for converting, and thereby upgrading, very heavy hydrocarbons in situ without combustion of the virgin hydrocarbon and the attendant degradation of products which accompany combustion operations. The process disclosed herein permits the production and utilization of heavy-hydrocarbon resources which are otherwise not economically recoverable by other methods and minimizes the amount of surface processing required to produce marketable petroleum products.